Viscoelastic surfactant based wellbore fluids and methods of use

ABSTRACT

A wellbore fluid that includes an aqueous based fluid; an amphoteric, viscoelastic surfactant; and a modified starch is disclosed. Methods of drilling subterranean wells, methods of reducing the loss of fluid out of subterranean wells, and methods of completing wellbores using aqueous-based fluids having an ampoteric, viscoelastic surfactant and a modified starch are also disclosed.

BACKGROUND OF INVENTION

1. Field of the Invention

Embodiments disclosed herein relate generally to wellbore fluids. Inparticular, embodiments disclosed herein relate to aqueous basedwellbore fluid that may find particular use in drilling a wellborethrough a producing interval of the formation.

2. Background Art

During the drilling of a wellbore, various fluids are typically used inthe well for a variety of functions. The fluids may be circulatedthrough a drill pipe and drill bit into the wellbore, and then maysubsequently flow upward through wellbore to the surface. During thiscirculation, a drilling fluid may act to remove drill cuttings from thebottom of the hole to the surface, to suspend cuttings and weightingmaterial when circulation is interrupted, to control subsurfacepressures, to maintain the integrity of the wellbore until the wellsection is cased and cemented, to isolate the fluids from the formationby providing sufficient hydrostatic pressure to prevent the ingress offormation fluids into the wellbore, to cool and lubricate the drillstring and bit, and/or to maximize penetration rate.

However, another wellbore fluid used in the wellbore following thedrilling operation is a completion fluid. Completion fluids broadlyrefer any fluid pumped down a well after drilling operations have beencompleted, including fluids introduced during acidizing, perforating,fracturing, workover operations, etc. A drill-in fluid is a specifictype of drilling fluid that is designed to drill and complete thereservoir section of a well in an open hole, i.e., the “producing” partof the formation. Such fluids are designed to balance the needs of thereservoir with drilling and completion processes. In particular, it isdesirable to protect the formation from damage and fluid loss, and notimpede future production. Most drill-in fluids contain several solidmaterials including viscosifiers, drill solids, and additives used asbridging agents to prevent lost circulation and as barite weightingmaterial to control pressure formation.

During drilling, the filtercake builds up as an accumulation of varyingsizes and types of particles. This filtercake must be removed during theinitial state of production, either physically or chemically (i.e., viaacids, oxidizers, and/or enzymes). The amount and type of drill solidsaffects the effectiveness of these clean up treatments. Also affectingthe effectiveness of the clean up of the wellbore prior to production isthe presence of polymeric additives, which may be resistant todegradation using conventional breakers.

Designing drill-in fluids which can guarantee minimum invasion into thereservoir rock is necessary for open hole completion wells. The industryhas proposed several ideas to deal with the problem, most of them basedon adding bridging agents to the fluid formulation. Such agents wouldblock pores near the well bore and, consequently, prevent additionalfluid to invade the rock.

Examples of formations in which problems often arise are highlypermeable and/or poorly consolidated formation and thus a techniqueknown as “under-reaming” may be employed. In conducting theunder-reaming process, the wellbore is drilled to penetrate thehydrocarbon-bearing zone using conventional techniques. A casinggenerally is set in the wellbore to a point just above thehydrocarbon-bearing zone. The hydrocarbon-bearing zone then may bere-drilled to a wider diameter, for example, using an expandableunder-reamer that increases the diameter of the wellbore. Under-reamingusually is performed using such special “clean” drilling fluids,drill-in fluids. Typically the drill-in fluids used in under-reaming areaqueous, dense brines that are viscosified with a gelling and/orcross-linked polymer to aid in the removal of formation cuttings.However, the expense of such fluids limits their general use in thedrilling process.

When the target subterranean formation has a high permeability asignificant quantity of the drilling fluid may be lost into theformation. Once the drilling fluid is lost into the formation, itbecomes difficult to remove. Removal of the aqueous based well fluids isdesired to maximize the production of the hydrocarbon in the formation.It is well known in the art that calcium- and zinc-bromide brines canform highly stable, acid insoluble compounds when reacted with theformation rock itself or with substances contained within the formation.These reactions often may substantially reduce the permeability of theformation to any subsequent out-flow of the desired hydrocarbons. Asshould be well known in the art, it is widely and generally acceptedthat the most effective way to prevent such damage to the formation isto limit fluid loss into the formation. Thus, providing effective fluidloss control is highly desirable to prevent damaging thehydrocarbon-bearing formation. For example such damage may occur during,completion, drilling, drill-in, displacement, hydraulic fracturing,work-over, packer fluid emplacement or maintenance, well treating, ortesting operations.

One class of viscosifiers commonly used in the petroleum industrycomprises polymeric structures starting with molecular weights ofhundreds of thousands to several million grams per mole. These large,chemically bonded structures are often crosslinked to further increasemolecular weight and effective viscosity per gram of polymer added tothe fluid. Such types of viscosifiers include polymeric additivesresistant to biodegration, extending the utility of the additives forthe useful life of the mud. Specific examples of biodegradationresistant polymeric additives employed include biopolymers, such asxanthans (xanthan gum) and scleroglucan; various acrylic based polymers,such as polyacrylamides and other acrylamide based polymers; andcellulose derivatives, such as dialkylcarboxymethylcellulose,hydroxyethylcellulose and the sodium salt of carboxy-methylcellulose,guar gum, phosphomannans, scleroglucans, glucans, and dextrane.

Because of the high temperature, high shear (caused by the pumping andplacement), high pressures, and low pH to which well fluids are exposed(“stress conditions”), the polymeric materials used to form fluid losspills and to viscosify the well fluids tend to degrade rather quickly.In particular, for many of the cellulose and cellulose derivatives (suchas HEC) used as viscosifiers and fluid control loss agents, significantdegradation occurs at temperatures around 200° F. and higher. HEC, forexample, is considered sufficiently stable to be used in an environmentof no more than about 225° F. Likewise, because of the high temperature,high shear, high pressures, and low pH to which well fluids are exposed,xanthan gum is considered sufficiently stable to be used in anenvironment of no more than about 290 to 300° F. These large moleculesare quite stable under the thermal conditions typically encountered in asubterranean reservoir. However, this thermal stability is believed tocontribute to decreased well productivity. As a result, expensive andoften corrosive breakers have been designed to destroy the molecularbackbone of these polymeric structures. These breakers are typicallyoxidizers or enzymes and are at best only partially effective withtypical reservoir cleanup less than 80% complete and more usually muchless than 50% complete.

Accordingly, there exists a continuing need for wellbore fluids that arenon-damaging to the formation and easily removed, particularly for usein drilling through a producing interval of a formation.

SUMMARY OF INVENTION

In one aspect, embodiments disclosed herein relate to a wellbore fluidthat includes an aqueous based fluid; an amphoteric, viscoelasticsurfactant; and a modified starch.

In another aspect, embodiments disclosed herein relate to a method ofdrilling a subterranean well that includes drilling the subterraneanwell using a rotary drilling rig and circulating a wellbore fluid in thesubterranean well, wherein the wellbore fluid comprises an aqueous basedcontinuous phase; an amphoteric, viscoelastic surfactant; and a modifiedstarch.

In another aspect, embodiments disclosed herein relate to a method ofreducing the loss of fluid out of a subterranean well that includesinjecting into the subterranean well a wellbore fluid comprising: anaqueous based continuous phase; an amphoteric, viscoelastic surfactant;and a modified starch.

In yet another aspect, embodiments disclosed herein relate to a methodof completing a wellbore that includes drilling the wellbore with awellbore fluid to form a filter cake on the walls thereof, the wellborefluid comprising: an aqueous based continuous phase; an amphoteric,viscoelastic surfactant; and a modified starch; emplacing a breakerfluid into the wellbore; and shutting in the well for a period of timesufficient to initiate breaking of the filter cake.

Other aspects and advantages of the invention will be apparent from thefollowing description and the appended claims.

DETAILED DESCRIPTION

In one aspect, embodiments disclosed herein relate to wellbore fluids.In particular, embodiments disclosed herein relate to aqueous basedwellbore fluid that may find particular use in drilling a wellborethrough a producing interval of the formation.

As discussed above, when drilling a wellbore, a fluid typically requiresa viscosifier, which may be, for example, biopolymers such as xanthan,guar or scleroglucan gum in water-based fluids, to provide enhancedviscosity and viscosity control, increased gel strength, and/orsuspension and removal of drilling cuttings during drilling operations.Further, some viscosifiers such as xanthan may also act as fluid losscontrol agent, in addition to providing rheological properties. As aresult, a filter cake may be formed on the wellbore wall that includessuch polymeric additives therein. Even after attempting to break such afilter cake prior to initiating production of the well, residual polymerfrequently remains on the walls. Thus, such residual polymer may havedeleterious effects on the formation, and on production of hydrocarbonsresiding therein.

Thus, in accordance with embodiments of the present disclosure, awater-based wellbore fluid may be formulated with at least oneviscoelastic surfactant and a modified starch to achieve the combinedrheological, fluid loss, and clean-up properties without incorporatingbiopolymers. Methods of drilling at least one interval using such fluidsand methods of completing and producing a well drilled with such a fluidare also disclosed herein. Further, while the fluids of the presentdisclosure may be particularly suitable for use in drilling a producinginterval of a wellbore, one skilled in the art would appreciate that nolimitation on the scope of the present invention exists. Rather, suchfluids may be used to drill any (and all) intervals of a wellboreirrespective of whether the interval corresponds to the producing or“pay zone” section.

To achieve the rheological properties desired for the fluids of thepresent disclosure, at least one amphoteric, viscoelastic surfactant maybe provided in the fluid. The term “amphoteric” refers to a compoundthat can act either as an acid or a base. Viscoelastic surfactants,generally, are relatively small molecules with each molecule beingtypically less than 500 grams per mole (i.e., molecular weight less than500). These small molecules will associate under certain conditions toform structures which resemble the polymer molecules but which are notstable structures. The individual molecules of surfactant may ratherassociate to form rod-like or spiraling-cylinder-like micelles.

By incorporating a viscoelastic surfactant in a fluid, the fluid may berendered viscoelastic. Viscoelastic fluids are those in which theapplication of stress gives rise to a strain that approaches itsequilibrium value relatively slowly. Therefore, viscoelastic fluids maybehave as a viscous fluid or an elastic solid, depending upon the stresson the system. Viscoelasticity in fluids caused by surfactants canmanifest itself in shear rate thinning behavior. For example, when sucha fluid is being pumped downhole, the fluid exhibits low viscosity,whereas the fluid returns to its more viscous state when the shearingforce is abated. This shear thinning effect may result from thestructure of the individual surfactant molecules, and the tendency ofthose molecules to form rod-link or spiraling cylinder-like micelles.Thus, the incorporation of a viscoelastic surfactant may allow for afluid to behave as a viscous fluid under low shear, and a low viscosityfluid under a higher shear. A viscoelastic fluid also has an elasticcomponent which manifests itself in yield value. This allows aviscoelastic fluid to suspend an insoluble material, for examplebridging solids or drill cuttings, for a greater time period than aviscous fluid of the same apparent viscosity to prevent gravityseparation. In addition, when the drilling fluid is under shearconditions and a free-flowing near-liquid, it must retain a sufficientlyhigh enough viscosity to carry all unwanted particulate matter from thebottom of the well bore to the surface.

In accordance with a particular embodiment of the present disclosure,the viscoelastic surfactant is preferably amphoteric. Suitableamphoteric surfactants are derivatives of aliphatic quaternary ammonium,phosphonium and sulphonium compounds, wherein the aliphatic radicalscontain from 8 to 18 carbon atoms, and may be straight chain orbranched, and further contain an anionic water-solubilizing group, suchas carboxyl, sulphonate, sulphate, phosphate or phosphonate. Inparticular, the amphoteric surfactant may be a compound represented bythe general structure:

where R1, R2, R3, R4, and R5 are carbon chains, saturated orunsaturated, straight, branched, or cyclic including aromatic groups, R1contains 8-26 carbons, R2 contains 2-10 carbons, and R3, R4, and R5contain 1-6 carbons; X is N, S, or P, and y is 0 or 1.

In a particular embodiment, the amphoteric surfactant may be an alkylbetaine or alkylamidopropyl betaine where R1 may be derived from variousfatty acids such as butyric acid (C4), caproic acid (C6), caprylic acid(C8), capric acid (C10), lauric acid (C12), mysristic acid (C14),palmitic acid (C16), stearic acid (C18), etc, in addition to unsaturatedfatty acids such as myristoleic acid (C14), palmitoleic acid (C16),oleic acid (C18), linoleic acid (C18), alpha-linoleic acid (C18), erucicacid (C22), etc, or mixtures thereof. Commercial examples of suchsurfactants include those sold under the trade name MIRATAINE® fromRhodia, Inc. (Cranbury, N.J.) including BET-O-type (oleamidopropylbetain) and BET-E-type (eurcamidopropyl betaine) surfactants, which maybe commercially available at various activities of active surfactant(e.g., 30-40%) in water with a winterizing agent such as propyleneglycol. Amounts of the active amphoteric surfactant according to thepresent invention may range from about 0.01 to about 30%, from about 0.5to about 10% in another embodiment, between about 1 and about 5% byweight of the wellbore fluid in yet another embodiment. However, oneskilled in the art would appreciate that other amounts may be used, solong as the surfactant is present in an amount sufficient to impart thedesired rheological effect by the formation of micelles within thewellbore fluid. In a particular embodiment, the amount of activeamphoteric surfactant may be selected based on the low shear rateviscosity desired for the particular application.

Further, in addition to a viscoelastic surfactant, which will impartrheological properties, a modified starch may be provided in thewellbore fluid to impart desired fluid loss control properties, even athigher temperatures. The modified starches used in the fluids of thepresent disclosure may include chemically modified starches, includingstarch treated with a number of multi-functional crosslinking agents. Ina particular embodiment, a chemically modified starch includes a starchhaving a portion of its hydroxyl groups replaced by either ester orether groups. In particular, a portion of the hydroxyl groups may beetherified with propylene oxide to form a hydroxypropyl starch oretherified with mono chloracetic acid to form a carboxymethyl starch;however, other alkoxylated or starch esters such as starch acetates mayalternatively be used. Further, one skilled in the art would appreciatethat other modifications are also envisioned. In a particularembodiment, a modified starch for use in a wellbore fluid of the presentdisclosure may include a starch etherified using propylene oxide in thepresence of sodium hydroxide and sodium sulfate.

When a crosslinked starch is desirable, suitable crosslinking agents mayinclude, for example, epichlorohydrin, phosphorus oxychloride,adipic-acetic anhydrides and sodium trimetaphosphate. Further, oneskilled in the art would appreciate that the base material forcrosslinking may be a chemically modified starch, such as a starchhaving a portion of its hydroxyl groups replaced by either ester orether groups. Selection between esterified/etherified starch and/orcrosslinked starch may, for example, be dependent on the particulardrilling operation (and formation) in which the fluid is being used. Forexample, one skilled in the art would appreciate that depending on theexpected temperatures (and thus requirements for temperature stability),crosslinking may provide additional thermal stability to the starch.

The starches which may be used as the base material in the modifiedstarches include starches derived from any plant source such as corn,wheat, rice, tapioca, sago, waxy maize, waxy rice, sorghum, potato, pea,roots containing a high starch content, etc. Starch consists of linkedanhydro-D-glucose units having either a mainly linear structure(amylose) or a branched structure (amylopectin). However, one skilled inthe art would appreciate that a single plant species may exist withcertain proportions of amylose and amylopectin, and that hybrids withvarying proportions may also exist. Further, it is known that “starch”may also refer to common starch, which contains both amylose andamylopectin molecules, or waxy starch, which is virtually allamylopectin molecules.

The crosslinked starches of the present disclosure may be prepared usingknown techniques by reacting starch with an appropriate crosslinkingagent in aqueous solution under alkaline conditions. The crosslinkedstarch slurry is then dried, such as by a heated drum dryer or extruder.Further, the starch granules are gelatinized either partially orcompletely when dried in the known manner. The product may be milled toobtain a dry product (at a desired particle size), which may then beincorporated into wellbore fluid at the drill site.

It is well known to measure the viscosity of crosslinked starch using aC. W. Brabender Visco-Amylo Graph. Using this measuring device, thestarches may be crosslinked to provide a Brabender peak viscosity ofabout 800 to about 1250, preferably about 920 to about 1150 Brabenderunits after about 40 to about 70 minutes at about 92° C. One skilled inthe art would appreciate that the amount of crosslinking agent used toachieve this degree of crosslinking will vary somewhat depending of theconditions and materials used. Typically, the amount of crosslinkingagent used may range from about 0.05% to 0.15% by weight of the starch;however, one skilled in the art would appreciate that the amount mayvary depending on the reagent used, the reaction conditions, the type ofstarch, and the desired degree of crosslinking, for example.

The cross-linked starches of the present invention are employed insubterranean treatment fluids in an effective amount to provide fluidloss control and educe fluid loss over a broad temperature range. Theeffective amount of cross-linked starches will vary depending on theother components of the subterranean treatment fluid, as well as thegeological characteristics and conditions of the subterranean formationin which it is employed. Typically, the cross-linked starch fluid losscontrol additive may be used in an amount of from about 1 pound to about10 pounds (lbs) of starch per barrel (bbl) of the subterranean treatmentfluid, preferably from about 3 to about 6 pounds per barrel.

Aqueous fluids that may form the continuous phase of the viscoelasticfluid may include at least one of fresh water, sea water, brine,mixtures of water and water-soluble organic compounds and mixturesthereof. For example, the aqueous fluid may be formulated with mixturesof desired salts in fresh water. Such salts may include, but are notlimited to alkali metal chlorides, hydroxides, or carboxylates, forexample. In various embodiments of the drilling fluid disclosed herein,the brine may include seawater, aqueous solutions wherein the saltconcentration is less than that of sea water, or aqueous solutionswherein the salt concentration is greater than that of sea water. Saltsthat may be found in seawater include, but are not limited to, sodium,calcium, sulfur, aluminum, magnesium, potassium, strontium, silicon,lithium, and phosphorus salts of chlorides, bromides, carbonates,iodides, chlorates, bromates, formates, nitrates, oxides, and fluorides.Salts that may be incorporated in a brine include any one or more ofthose present in natural seawater or any other organic or inorganicdissolved salts. Additionally, brines that may be used in the drillingfluids disclosed herein may be natural or synthetic, with syntheticbrines tending to be much simpler in constitution. In one embodiment,the density of the drilling fluid may be controlled by increasing thesalt concentration in the brine (up to saturation). In a particularembodiment, a brine may include halide or carboxylate salts of mono- ordivalent cations of metals, such as cesium, potassium, calcium, zinc,and/or sodium. Further, when greater temperature stability is desired,one skilled in the art would appreciate that it may be desirable toinclude water miscible solvents such as various glycols to improve thethermal stability of the fluid system.

Further, in a particular embodiment, at least one solid material, suchas a bridging agent or weighting agent, may be included in the wellborefluids of the present disclosure. Bridging agents, weighting agents ordensity materials suitable for use in some embodiments include galena,hematite, magnetite, iron oxides, illmenite, barite, siderite,celestite, dolomite, calcite, and the like. Alternatively, suchmaterials may also include fibrous cellulosic materials, graphite, coke,perlite, etc. The quantity of such material added, if any, depends uponthe desired density of the final composition. Typically, weight materialis added to result in a drilling fluid density of up to about 24 poundsper gallon. The weight material is preferably added up to 21 pounds pergallon and most preferably up to 19.5 pounds per gallon. In a particularembodiment, calcium carbonate may be used as a bridging agent in forminga filter cake.

Further, in a particular embodiment, a miscible amine may be used as apH buffer and/or thermal extender to prevent acid-catalyzed degradationof polymers present in the fluid. A suitable miscible amine may includetriethanolamine; however, one skilled in the art would appreciate thatother miscible amines such as methyldiethanol amine (MDEA),dimethylethanol amine (DMEA), diethanol amine (DEA), monoethanol amine(MEA), or other suitable tertiary, secondary, and primary amines andammonia could be used in the fluids of the present disclosure. Suitableamounts may range from 0.1% to 10% by weight of the miscible amine.

Other additives that are typically included in wellbore fluids includefor example, fluid loss control agents, mutual solvents, wetting agents,organophilic clays, viscosifiers, surfactants, dispersants, interfacialtension reducers, mutual solvents, thinners, thinning agents andcleaning agents. The addition of such agents should be well known to oneof ordinary skill in the art of formulating drilling fluids and muds.

Conventional methods may be used to prepare the fluids disclosed hereinin a manner analogous to those normally used, to prepare conventionalwater-based drilling fluids. In one embodiment, a desired quantity ofwater-based fluid and a suitable amount of viscoelastic surfactant andcrosslinked starch as described above, are mixed together and theremaining components of the fluid added sequentially with continuousmixing.

Further, a breaker fluid may be emplaced in a wellbore drilled with thefluids of the present disclosure when clean-up/removal of a filter cakeis desired. The breaker may be selectively emplaced in the wellbore, forexample, by spotting the fluid through a coil tube or by bullheading. Adownhole anemometer or similar tool may be used to detect fluid flowsdownhole that indicate where fluid may be lost to the formation. Variousmethods of emplacing a pill known in the art are discussed, for example,in U.S. Pat. Nos. 4,662,448, 6,325,149, 6,367,548, 6,790,812, 6,763,888,which are herein incorporated by reference in their entirety. However,no limitation on the techniques by which the breaker fluid of thepresent disclosure is emplaced is intended on the scope of the presentapplication. After a period of time sufficient, i.e., several days, toallow for disruption or fragmentation of the filter cake and the fluidmay be returned to the surface for collection and subsequent recoverytechniques. Subsequent washes of the wellbore with wash fluids may bedesirable to ensure complete removal of filter cake material remainingtherein. Various types of breakers are known in the art, and nolimitation is intended on the type of breaker(s) that may be used todisrupt filtercakes formed from wellbore fluids of the presentdisclosure. Rather, it is envisioned that any of enzyme, solvent,chelant, acidizing, or oxidizing breakers may be used in breaking suchfiltercakes. In a particular embodiment, it may be desirable to includean enzyme/solvent/acid breaker combination for breaking the crosslinkedstarch, viscosified surfactant, and bridging solids.

Examples

An exemplary fluid and comparative sample fluid (formulated withconventional xanthan viscosifier) were formulated having the followingcomponents, as shown below in Table 1. Specifically, the componentsinclude ECF-975, an alkylamidopropyl betaine, SAFECARB®, a calciumcarbonate bridging solid, ECF-1758, a crosslinked potato starch, FLOVISPLUS™, xanthan gum, and FLOTROL™, a starch derivative, all of which areavailable from M-I LLC (Houston, Tex.). The fluids were formulated bymixing with a Hamilton Beach mixer for 10-30 min.

TABLE 1 Fluid 1 Fluid 2 9.2 ppg NaCl (lb/bbl) 350.9 Tap Water (lb/bbl)308.0 Dry KCl (lb/bbl) 10.7 starch derivative (lb/bbl) 1.25 ECF-975(lb/bbl) 1.0 Dry NaCl (lb/bbl) 42.0 ethanolamine (lb/bbl) 0.6 xanthangum (lb/bbl) 6.0 SAFECARB ® 2 (lb/bbl) 14.0 MgO (lb/bbl) 0.5 SAFECARB ®10 (lb/bbl) 21.0 SAFECARB ® 40 (lb/bbl) 50 ECF-1758 (lb/bbl) 8.0Greencide 0.1

Rheological properties were determined using a Fann Model 35 viscometer,available from Fann Instrument Company. Fluid loss was measured with asaturated API high temperature, high pressure (HTHP) cell. The resultsare shown below in Table 2.

TABLE 2 Post Post Heat Heat Initial Aging Initial Aging Fluid 1 Fluid 1Fluid 2 Fluid 2 Rheology Temp 120 120 120 120 (120° F.) 600 rpm 61 53 5157 300 rpm 45 35 39 45 200 rpm 40 30 34 40 100 rpm 32 20 28 31  6 rpm 1614 13 15  3 rpm 11 10 11 12 GELS 10″ (lbs/100 ft²) 10 5 10 12 GELS 10′(lbs/100 ft²) 11 8 13 15 Apparent Viscosity (cP) 30.5 26.5 25.5 28.5Plastic Viscosity (cP) 16 18 12 12 Yield Point (lbs/100 ft²) 29 17 27 33LSRV 1 min (cps) 93980 52389 38782 37292 2 min (cps) 90381 51989 4089138192 3 min (cps) 94382 49989 40992 38492 API Fluid Loss (mL) — 4.6 —3.8 pH 8.82 9.20 9.06 9.18 Mud Weight 9.7 9.7 9.73 9.73

Filter cakes built from the above fluids were subjected to a modifiedHigh Temperature High Pressure (HTHP) Filtration test. The HTHPFiltration test uses a HTHP cell fitted with a fitted disc as a porousmedium, on which a filter cake is built. In this example, the filtercakes were built on 20 micron disks. Upon application of 500 psi at 180°F. to the disks of filter cake, effluent was collected as shown in Table3.

TABLE 3 Post Heat Aging Post Heat Aging Fluid 1 Fluid 2 Spurt 4.4 3.8 1min 2.0 1.6 4 min 3.6 2.6 9 min 4.8 2.6 16 min 6.0 4.6 25 min 6.8 5.8 30min 7.4 6.4 36 min 7.8 6.8 30 min doubled 14.8 12.8 Modified HTHP 19.216.6 Fluid Losa thickness 1/16″ 1/16″

Further, contamination effects on Fluid 1, including lubricant, inertsolids, and clay were tested. KLASTOP™ is a polyether amine additivethat inhibits clay hydration, which is commercially available from M-ILLC (Houston, Tex.) The contamination amounts are shown below in Table4.

TABLE 4 Fluid 1 + Inert Fluid 1 + Clay + Fluid 1 + Fluid 1 + Lub SolidsFluid 1 + Clay KLASTOP Solids + Lub Fluid 1 339.5/394.2 339.5/394.2339.5/394.2 339.5/394.2 339.5/394.2 STARGLIDE lubricant 10.5/9.5 — — —10.5/9.5  (3% v/v) Rev Dust (3% v/v) — 17   — — 17   Silica Flour (3%v/v) — 10.3 — — 10.3 Hymod Clay (3%) — — 27.3 27.3 — KLASTOP (3% v/v) —— — 10.5/9.5  —

The rheological properties of the contaminated fluids were tested andare shown below in Table 5.

TABLE 5 Fluid 1 + Fluid 1 + Inert Clay + Fluid 1 + Fluid 1 + Lub SolidsFluid 1 + Clay KLASTOP Solids + Lub Rheology Temp 120 120 120 120 120(120° F.) 600 rpm 39 48 90 82 34 300 rpm 25 30 62 59 20 200 rpm 20 25 4950 16 100 rpm 13 17 34 40 10  6 rpm 5 5 12 19 4  3 rpm 3 4 10 16 3 GELS10″ (lbs/ 3 4 8 15 3 100 ft²) GELS 10′ (lbs/100 ft²) 4 5 15 18 4Apparent Viscosity 19.5 24 45 41 17 (cP) Plastic Viscosity (cP) 14 18 2823 14 Yield Point (lbs/ 11 12 34 36 6 100 ft²) LSRV 1 min (cps) 319921095 82482 — 8398 2 min (cps) 3099 19496 95280 77983 8298 3 min (cps)3199 17396 92381 71585 7998 API Fluid Loss (mL) 2 3.4 3.4 2.8 2.2 pH9.24 9.43 9.23 9.57 9.06 Mud Weight 9.62 10.03 10.03 9.97 9.97

Additionally, the modified HTHP filtration test was also performed onthe contaminated fluid. The results are shown in Table 6.

TABLE 6 Fluid 1 + Fluid 1 + Inert Clay + Fluid 1 + Fluid 1 + Lub SolidsFluid 1 + Clay KLASTOP Solids + Lub Spurt 9.4 2.0 32.2 5.4 1.8 1 min 0.42.2 1.8 2.2 1.6 4 min 1.6 2.8 3.2 3.4 3.0 9 min 2.2 4.0 4.4 5.0 3.4 16min 2.8 5.0 5.4 6.2 4.2 25 min 3.4 6.0 6.2 7.4 4.8 30 min 3.8 6.6 7.48.2 5.0 36 min 4.0 7.0 8.2 8.6 5.4 30 min doubled 7.6 13.2 14.8 16.410.0 Modified HTHP 17.0 15.2 47.0 21.8 11.8 Fluid Loss thickness 1/16″2/16″ 3/16″ 2/16″ 1/16″

A breaker fluid was formulated as shown below in Table 7. Specifically,the components include D-SOLVER™, a chelating agent, WELLZYME® A, anenzyme breaker, and D-SPERSE™, a surfactant, all of which are availablefrom M-I LLC (Houston, Tex.)

TABLE 7 Component Amount (mL/g) per bbl pH 9.0 ppg KCl 66.3/71.6D-SOLVER ™ 262.5/305.8 4.84 KOH pH to 5 0.125 5.04 WELLZYME ® A17.5/19.7 D-SPERSE ™ 1.8/1.9 4.87

Breaking of filter cake built from Fluids 1 were tested as follows. 20micron discs were pre-soaked with 3% KCl, loaded into a modified HTHPcell, which was filled with 3% KCl. The closed cell was placed in a FlowBack tester, where the amount of time for 200 mL to pass through thedisc in the production and injection at 5 psi was performed. The KCl wasdecanted off and the cells were filled with the fluids. A pressure of500 psi was applied to the cells and the temperature was allowed toreach 180° F. After reaching 180° F., a fluid loss test was performedfor 4 hours, and the filtrate collections recorded. Excess fluid wasdecanted/removed from the cell, and the breaker fluid shown in Table 7was added thereto. A pressure of 500 ps for 30 min (or until 30 mL ofeffluent was collected) was applied. The pressure was reduced to 50 psiand the cell was shut in, allowing the filter cake to soak for 72 hoursat 180° F. with 50 psi. After 72 hours, the residual breaker wasdecanted from the cell, and the cell was filled with 3% KCl. The timefor 200 mls to flow in the production and injection directions wasmeasured at 5 psi. Fluid 1 shows Return to Flow percentages of 97.6 and99.1% for production and injection rates, respectively.

Advantageously, embodiments of the present disclosure may provide for atleast one of the following. Wellbore fluids of the present disclosuremay find particular use for drilling through producing intervals of aformation, where it may be particularly desirable to increase clean-upabilities, to maximize hydrocarbon recovery. In particular, the fluidsof the present disclosure may be particularly desirable for drillingsuch target intervals based on the rheological properties, ease ofremoval, flowback qualities (including slight stimulation of well,increasing flowback), and compatability with completion techniques.Further, desirable rheological properties include 1) the viscosity athigh shear values is sufficiently low to guarantee low pressure dropsduring drilling and 2) the gel and viscosity values at low shear valuesare sufficiently high to keep the cuttings in suspension when the fluidcirculation is stopped, thus avoiding the formation of deposits. Asdescribed above, the cross-linked starch fluid loss additives of thisinvention provide good fluid loss control over a broad temperature rangeand in an environment where salinity, shear and high temperaturetolerance are often required.

While the invention has been described with respect to a limited numberof embodiments, those skilled in the art, having benefit of thisdisclosure, will appreciate that other embodiments can be devised whichdo not depart from the scope of the invention as disclosed herein.Accordingly, the scope of the invention should be limited only by theattached claims.

1-10. (canceled)
 11. A method of drilling a subterranean well,comprising: drilling the subterranean well using a rotary drilling rigand circulating a wellbore fluid in the subterranean well, wherein thewellbore fluid comprises: an aqueous based continuous phase; anamphoteric, viscoelastic surfactant; and a modified starch.
 12. Themethod of claim 11, wherein the wellbore fluid is used to drill aproducing interval of the well.
 13. The method of claim 12, wherein adifferent wellbore fluid is used to drill the well prior to theproducing interval.
 14. The method of claim 11, wherein the amphotericsurfactant comprises a compound represented by the general structure:

where R1, R2, R3, R4, and R5 are carbon chains, saturated orunsaturated, straight, branched, or cyclic including aromatic groups, R1contains 8-26 carbons, R2 contains 2-10 carbons, and R3, R4, and R5contain 1-6 carbons; X is N, S, or P, and y is 0 or
 1. 15. The method ofclaim 11, wherein the modified starch comprises at least one of corn,wheat, rice, tapioca, sago, waxy maize, waxy rice, sorghum, potato, andpea as a starch source.
 16. A method of reducing the loss of fluid outof a subterranean well, comprising: injecting into the subterranean wella wellbore fluid comprising: an aqueous based continuous phase; anamphoteric, viscoelastic surfactant; and a modified starch.
 17. Themethod of claim 16, wherein the amphoteric surfactant comprises acompound represented by the general structure:

where R1, R2, R3, R4, and R5 are carbon chains, saturated orunsaturated, straight, branched, or cyclic including aromatic groups, R1contains 8-26 carbons, R2 contains 2-10 carbons, and R3, R4, and R5contain 1-6 carbons; X is N, S, or P, and y is 0 or
 1. 18. The method ofclaim 16, wherein the modified starch comprises at least one of corn,wheat, rice, tapioca, sago, waxy maize, waxy rice, sorghum, potato, andpea as a starch source.
 19. A method of completing a wellbore,comprising: drilling the wellbore with a wellbore fluid to form a filtercake on the walls thereof, the wellbore fluid comprising: an aqueousbased continuous phase; an amphoteric, viscoelastic surfactant; and amodified starch; emplacing a breaker fluid into the wellbore; andshutting in the well for a period of time sufficient to initiatebreaking of the filter cake.
 20. The method of claim 19, furthercomprising gravel packing at least one interval of the wellbore.
 21. Themethod of claim 19, further comprising: circulating a wash fluid throughthe wellbore prior to and/or after emplacing a breaker fluid.
 22. Themethod of claim 19, further comprising: collecting the breaker fluidhaving at least a portion of the broken invert emulsion filter cakeemulsified therein.
 23. The method of claim 19, further comprising:initiating production of formation fluids through the wellbore.
 24. Themethod of claim 19, wherein the amphoteric surfactant comprises acompound represented by the general structure:

where R1, R2, R3, R4, and R5 are carbon chains, saturated orunsaturated, straight, branched, or cyclic including aromatic groups, R1contains 8-26 carbons, R2 contains 2-10 carbons, and R3, R4, and R5contain 1-6 carbons; X is N, S, or P, and y is 0 or
 1. 25. The method ofclaim 19, wherein the modified starch comprises at least one of corn,wheat, rice, tapioca, sago, waxy maize, waxy rice, sorghum, potato, andpea as a starch source.